1. Field of the Invention
The present invention relates to the production of hydrocarbon wells. More particularly the invention relates to the use of pressurized steam to encourage production of hydrocarbons from a wellbore. More particularly still, the invention relates to methods and apparatus to inject steam into a wellbore at a controlled flow rate in order to urge hydrocarbons to another wellbore.
2. Description of the Related Art
To complete a well for hydrocarbon production, a wellbore drilled in the earth is typically lined with casing which is inserted into the well and then cemented in place. As the well is drilled to a greater depth, smaller diameter strings of casing are lowered into the wellbore and attached to the bottom of the previous casing string. Casing strings of an ever-decreasing diameter are placed into a wellbore in a sequential order, with each subsequent string necessarily being smaller than the one before it.
Increasingly, lateral wellbores are created in wells to more completely or effectively access hydrocarbon-bearing formations. Lateral wellbores may be formed off of a vertical wellbore, typically from the lower end of the vertical wellbore, and may be directed outwards through the use of some means of directional drilling, such as a diverter. The end of the lateral wellbore which is closest to the vertical wellbore is the heel, while the opposite end of the lateral wellbore is the toe. Alternatively, lateral wellbores may be formed in a formation merely by directional drilling rather than formed off of a vertical wellbore. After a lateral wellbore is formed, it may be lined with casing or may remain unlined.
Artificial lifting techniques are well known in the production of oil and gas. The hydrocarbon formations accessed by most wellbores do not have adequate natural pressure to cause the hydrocarbons to rise to the surface on their own. Rather, some type of intervention is used to encourage production. In some instances, pumps are used either in the wellbore or at the surface of the well to bring fluids to the surface. In other instances, gas is injected into the wellbore to lighten the weight of fluids and facilitate their movement towards the surface.
In still other instances, a compressible fluid like pressurized steam is injected into an adjacent wellbore to urge the hydrocarbons towards a producing wellbore. This is especially prevalent in a producing field with formations having heavy oil. The steam, through heat and pressure, reduces the viscosity of the oil and urges or “sweeps” it towards another wellbore. In a simple arrangement, an injection well includes a cased wellbore with perforations at an area of the wellbore adjacent a formation or production zone of interest. The production zones are typically separated and isolated from one another by layers of impermeable material. The area of the wellbore above and below the perforations is isolated with packers and steam is injected into the wellbore either by using the casing itself as a conduit or through the use of a separate string of tubulars coaxially disposed in the casing. The steam is generated at the surface of the well and may be used to provide steam to several injection wells at once. If needed, a simple valve monitors the flow of steam into the wellbore. While the forgoing example is adequate for injecting steam into a single zone, in vertical wellbores, there are more typically multiple zones of interest adjacent a wellbore and sometimes it is desirable to inject steam into multiple zones at different depths of the same wellbore. Because each wellbore includes production zones with varying natural pressures and permeabilities, the requirement for the injected steam can vary between zones, creating a problem when the steam is provided from a single source.
One approach to injecting steam into multiple zones is simply to provide perforations at each zone and then inject the steam into the casing. While this technique theoretically exposes each zone to steam, it has practical limitations since most of the steam enters the highest zone in the wellbore (the zone having the least natural pressure or the highest permeability). In another approach, separate conduits are used between the injection source and each zone. This type of arrangement is shown in FIG. 1. FIG. 1 illustrates a vertical wellbore 100 having casing 105 located therein with perforations 110 in the casing adjacent each of three separate zones of interest 115, 120, 125. As is typical with a wellbore, a borehole is first formed in the earth and subsequently lined with casing. An annular area formed between the casing and the borehole is filled with cement (not shown) which is injected at a lower end of the wellbore. Some amount of cement typically remains at the bottom of the wellbore. The upper and intermediate zones are isolated with packers 130 and a lower end of one tubular string 135, 140, 145 terminates within each isolated zone. A steam generator 150 is located at the surface of the well and a simple choke 155 regulates the flow of the steam into each tubular. This method of individual tubulars successfully delivers a quantity of steam to each zone but regulation of the steam to each zone requires a separate choke. Additionally, the apparatus is costly and time consuming to install due to the multiple, separate tubular strings 135, 140, 145.
More recently, a single tubular string has been utilized to carry steam in a single wellbore to multiple zones of interest. In this approach, an annular area between the tubular and the zone is isolated with packers and a nozzle located in the tubing string at each zone delivers steam to that zone. The approach suffers the same problems as other prior art solutions in that the amount of steam entering each zone is difficult to control and some zones, because of their higher natural pressure or lower permeability, may not receive any steam at all. While the regulation of steam is possible when a critical flow of steam is passed through a single nozzle or restriction, these devices are inefficient and a critical flow is not possible if a ratio of pressure in the annulus to pressure in the tubular becomes greater than 0.56. In order to ensure a critical flow of steam through these prior art devices, a source of steam at the surface of the well must be adequate to ensure an annulus/tubing pressure ratio of under 0.56.
Critical flow is defined as flow of a compressible fluid, such as steam, through a nozzle or other restriction such that the velocity at least one location is equal to the sound speed of the fluid at local fluid conditions. Another way to say this is that the Mach number of the fluid is 1.0 at some location. When the condition occurs, the physics of compressible fluids requires that the condition will occur at the throat (smallest restriction) of the nozzle. Once sonic velocity is reached at the throat of the nozzle, the velocity, and therefore the flow rate, of the gas through the nozzle cannot increase regardless of changes in downstream conditions. This yields a perfectly flat flow curve so long as critical flow is maintained.
Another disadvantage of the forgoing arrangements relates to ease of changing components and operating characteristics of the apparatus. Over time, formation pressures and permeability associated with different zones of a well change and the optimal amount (flow rate) and pressure of steam injected into these zones changes as well. Typically, a different choke or nozzle is required to change the characteristics (flow rate and steam quality) of the injected steam. Because the nozzles are an integral part of a tubing string in the conventional arrangements, changing them requires removal of the string, an expensive and time-consuming operation.
Another problem with prior art injection methods involves the distribution of steam components. Typically, steam generated at a well site for injection into hydrocarbon bearing formations is made up of a component of water and a component of vapor. In one example, saturated steam that is composed of 70 percent vapor and 30 percent water by mass is distributed to several steam injection wells. Because the vapor and water have different flow characteristics, it is common for the relative proportions of water and vapor to change as the steam travels down a tubular and through some type of nozzle. For example, it is possible to inadvertently inject mostly vapor into a higher formation while injecting mostly water into lower formations. Because the injection process relies upon an optimum mixture of steam components, changes in the relative proportions of water and vapor prior to entering the formations is a problem that affects the success of the injection job.
Additional problems are also encountered with injection methods involving lateral wellbores. Although vertical wellbores typically have multiple zones of interest which must be treated, lateral wellbores ordinarily have only one zone of interest along the length of the lateral wellbore. Therefore, different pressures for different zones of interest, which are often desired for treating vertical wellbores, are not necessary in treating the zone of interest in the lateral wellbore. For lateral wellbores, it is desirable for the entire zone of interest to be treated equally with compressible fluid at the same pressure along the length of the lateral wellbore.
Ordinarily, steam is injected from the heel of the lateral wellbore. Because the injection is from the heel of the wellbore, the steam often has a higher pressure at the heel of the wellbore than at the toe due to pressure loss in the steam resulting from frictional resistance along the length of the wellbore as the steam travels downstream. As a result, as steam travels along the horizontal wellbore, its pressure typically undesirably varies along the length of the wellbore.
Along the length of the lateral wellbore, the steam also tends to separate, with the liquid phase flowing along the bottom of the wellbore and the vapor phase flowing into the upper portion of the wellbore. Because the phases tend to separate, the steam injected into the zone of interest along the wellbore may not be uniform in phase components. It is desirable for the steam to have a uniform phase distribution (liquid to vapor ratio) along the length of the lateral wellbore so that the zone of interest is treated equally along its length.
There is a need therefore, for an apparatus and method of injecting steam into multiple zones at a controlled flow rate and pressure in a single wellbore that is more efficient and effective than prior art arrangements. There is a further need for an injection apparatus with components that can be easily changed. There is a further need for an injection system that is simpler to install and remove. There is yet a further need to provide steam to multiple zones in a wellbore in predetermined proportions of water and vapor. There is yet a further need for a single source of steam provided to multiple, separate wellbores using a controlled flow rate. There is yet a further need for an apparatus and method for injecting steam into a zone of interest along the length of a lateral wellbore at a controlled flow rate and pressure. There is yet a further need for an apparatus and method for injecting steam into a zone of interest along the length of a lateral wellbore in predetermined proportions of water and vapor.